1. Field of the Invention
The present invention relates to a split seal for a progressive cavity pump (PCP) drive head stuffing box.
2. Description of the Related Art
FIG. 1 illustrates a known progressing cavity pump (PCP) system 10 installed over a wellbore 2. The wellbore 2 is partially lined with casing 4 which is cemented 5 to an inner surface of the wellbore 2. The wellbore 2 extends into a hydrocarbon-bearing formation 7, such as a crude oil formation. The system 10 includes a typical progressing cavity pump drive head 12, a wellhead frame 14, a stuffing box 16, an electric motor 18, and a belt and sheave drive system 20, all mounted on a flow tee 22. Alternatively, the drive system 20 may be gear driven. The flow tee 22 is shown with a blow out preventer 24 which is, in turn, mounted on a wellhead 25. The drive head supports and drives a drive shaft 26, generally known as a “polished rod”. The polished rod 26 is supported and rotated by a polish rod clamp 28, which engages an output shaft 30 of the drive head by milled slots (not shown) in both parts. Wellhead frame 14 is open sided in order to expose polished rod 26 to allow a service crew to install a safety clamp on the polished rod and then perform maintenance work on stuffing box 16. Polished rod 26 rotationally drives a drive string 32, which, in turn, drives a progressing cavity pump 34.
Typically, the drive string 32 is a sucker rod string. Alternatively, the drive string may be a continuous rod (COROD) string, a coiled tubing string, or a jointed tubing string. The pump 34 has a stator 44a,b (see FIGS. 1A,B) coupled to production tubing 6 and a rotor 46 (see FIGS. 1A,B) coupled to the drive string 32. The pump 34 is located at the bottom of the wellbore 2 to produce well fluids to the surface, via the production tubing 6, through the wellhead. Stuffing box 16 is mounted below the drive head 12 and mounted in the wellhead frame 14 such that it can be serviced from below the drive head 12 without removing it. This necessitates mounting the drive head higher, constrains the design, and means a difficult service job.
FIG. 1A is a sectional view of the prior art PC pump 34a. Pump housing 42 contains an elastomeric stator 44a having multiple lobes 55 formed in an inner surface thereof. The pump housing 42 is usually made from metal, preferably steel. The stator 44a has five lobes 55, although the stator may have two or more lobes. Inside the stator 44a is a rotor 46, the rotor 46 having one lobe fewer than the stator 44a formed in an outer surface thereof. The inner surface of the stator 44a and the outer surface of the rotor 46 also twist along respective longitudinal axes, thereby each forming a substantially helical-hypocycloid shape. The rotor 46 is usually made from metal, preferably steel. The rotor 46 and stator 44a interengage at the helical lobes to form a plurality of sealing surfaces 60. Sealed chambers 47 between the rotor 46 and stator 44a are also formed. In operation, rotation of the sucker rod or COROD string causes the rotor 46 to nutate or precess within the stator 44a as a planetary gear would nutate within an internal ring gear, thereby pumping production fluid through the chambers 47. The centerline of the rotor 46 travels in a circular path around the centerline of the stator 44a. 
One drawback in such prior art motors is the stress and heat generated by the movement of the rotor 46 within the stator 44a. There are several mechanisms by which heat is generated. The first is the compression of the stator elastomer 44a by the rotor 46, known as interference. Radial interference, such as five-thousandths of an inch to thirty-thousandths of an inch, is provided to seal the chambers to prevent leakage. The sliding or rubbing movement of the rotor 46 combined with the forces of interference generates friction. In addition, with each cycle of compression and release of the elastomer 44a, heat is generated due to internal viscous friction among the elastomer molecules. This phenomenon is known as hysteresis. Cyclic deformation of the elastomer occurs due to three effects: interference, centrifugal force, and reactive forces from pumping. The centrifugal force results from the mass of the rotor moving in the nutational path previously described. Reactive forces from torque generation are similar to those found in gears that are transmitting torque. Additional heat input may also be present from the high temperatures downhole.
Because elastomers are poor conductors of heat, the heat from these various sources builds up in the thick sections 50a-e of the stator lobes 55. In these areas the temperature rises higher than the temperature of the circulating fluid or the formation. This increased temperature causes rapid degradation of the elastomer 44a. Also, the elevated temperature changes the mechanical properties of the elastomer 44a, weakening each of the stator lobes as a structural member and leading to cracking and tearing of sections 50a-e, as well as portions 45a-e of the elastomer at the lobe crests. This design can also produce uneven rubber strain between the major and minor diameters of the pumping section. The flexing of the lobes 55 also limits the pressure capability of each stage of the pumping section by allowing more fluid slippage from one stage to the subsequent stages below.
Advances in manufacturing techniques have led to the introduction of even wall PC pumps 34b as shown in FIG. 1B. A thin tubular elastomer layer 70 is bonded to an inner surface of the stator 44b or an outer surface of the rotor 46 (layer 70 bonded on stator 44b as shown). The stator 44b is typically made from metal, preferably steel. These pumps 34b provide more power output than the traditional designs above due to the more rigid structure and the ability to transfer heat away from the elastomer 70 to the stator 44b. With improved heat transfer and a more rigid structure, the new even wall designs operate more efficiently and can tolerate higher environmental extremes. Although the outer surface of the stator 44b is shown as round, the outer surface may also resemble the inner surface of the stator. Further, the rotor 46 may be hollow.
FIG. 1C is a sectional view of the prior art retrofit stuffing box 16r. The retrofit stuffing box 16r includes a housing that has a first portion 112ra and a second or base portion 112rb. The second or base portion 112rb of the housing underlies first portion 112ra and is joined to first potion 112ra by bolts 113. The second portion 112rb has apertures 115 adapted to receive screws or other securing devices for the purpose of mounting stuffing box 16r. The stuffing box 16r includes an internal sleeve 114 positioned within the first portion 112ra of the housing. A first bearing 116 and a second bearing 118 are positioned in an annular space 120 between internal sleeve 114 and 112ra of the housing, such that internal sleeve 114 is journalled for rotation within the first portion 112ra of the housing. First bearing 116 is positioned within a bearing sleeve 122. Thrust washer 128 carries a first seal 124 and second seal 126. First bearing 116 is separated from second bearing 118 by a bearing separator 130. Second bearing 118 engages a shoulder 119 that limits its movement within annular space 120. A snap ring 127 is positioned above thrust washer 128 that also limits movement within annular space 120. A leak cock 132 is provided on first portion 112ra of the housing for supplying lubricant to first bearing 116 and second bearing 118.
A shaft cap 134 and static seals 136 are positioned within internal sleeve 114 to engage the drive shaft 26. Bolts 140 are used to tighten a rod clamp 142 around the drive shaft 26 in order to prevent the drive shaft 26 from being withdrawn from internal sleeve 114.
Referring also to FIG. 1D, a mechanical seal 144 is disposed in annular space 120 between internal sleeve 114 and first portion 112ra of the housing to block the passage of produced well fluids into first bearing 116 and second bearing 118. Mechanical seal 144 has a first body 146 with a first sealing surface 150 and a second body 148 with a second sealing surface 156. First body 146 is secured by set screws 152 to and rotates with internal sleeve 114. An o-ring seal 154 is positioned between first body 146 and internal sleeve 114 and serves a static sealing function. Second body 148 is secured by pins 158 to and remains stationary with housing 110. Pins 158 project into travel grooves 160 in first portion 111 of housing 110 so as to permit second body 148 to travel axially along groove 160 relative to first portion 112ra of the housing. An o-ring seal 162 is provided between second body 148 and the first portion 112ra of the housing and serves a static sealing function.
Belville springs 164 are provided for biasing first sealing surface 150 and second sealing surface 156 in sealing engagement. A grease nipple 166 is provided on first portion 112ra of the housing for supplying lubricant to mechanical seal 144. A bushing 168 is provided between second portion 112rb of housing and the drive shaft 26.
Operation of the stuffing box 16r is as follows. The drive shaft 26 is prevented from being withdrawn from internal sleeve 114 by rod clamp 142 and bolts 140. During operation, internal sleeve 114 rotates the drive shaft 26. Rotational movement of internal sleeve 114 is accommodated by first bearing 116, second bearing 118, bushing 168 and thrust washer 128. Static seal 136 is positioned to prevent leakage between the drive shaft 26 and internal sleeve 114. Static seal 154 is positioned to prevent leakage between first body 146 and internal sleeve 114. Static seal 162 is positioned to prevent leakage between second body 148 and the first portion 112ra of the housing. Mechanical seal 144 is disposed in annular space 120 between internal sleeve 14 and the first portion 112ra of the housing to block the passage of produced well fluids into first bearing 116 and second bearing 118. Second sealing face 156 of second body 148 engages first sealing face 150 of first body 146 to form mechanical seal 144, thereby preventing any passage of produced well fluids. Spring 164 maintains the sealing faces engaged at all times, even as wear occurs.
The sealing system for stuffing box 16r, as described above, has very high pressure dynamic capability. It can operate at pressures at or above 3500 p.s.i. without leakage. At ambient temperatures, stuffing box 10 does not require any external cooling. For high temperature applications, external cooling can be added to stuffing box 16r. 
FIG. 1E illustrates a typical progressing cavity pump drive head 12 with an integral stuffing box 16i mounted on the bottom of the drive head 12 and corresponding to that portion of the system in FIG. 1 which is above the dotted and dashed line 40. The integral stuffing box 16i reduces the height of the installation because there is no wellhead frame 14 and also reduces cost because there is no wellhead frame 14 and there are fewer parts since the stuffing box 16i is integrated with the drive head 12. The integral stuffing box is specially configured for a particular drive head 12 whereas the retrofit stuffing box is universal for any drive head 12.
FIG. 1F is a sectional view of the integral stuffing box 16i which includes a housing 112ia and an internal sleeve 114 positioned within housing 112. A first bearing 116, a second bearing 118, a thrust washer 128, and a bushing 168 are positioned in an annular space 120 between internal sleeve 114 and housing 112ia, such that internal sleeve 114 is journalled for rotation within housing 112. First bearing 116 is positioned within a bearing sleeve 122. Thrust washer 128 prevents axial movement of internal sleeve 114, so that internal sleeve 114 does not get pushed up out of position. Thrust washer 128 carries a first seal 124 and second seal 126. First bearing 116 is separated from second bearing 118 by a bearing separator 130. Second bearing 118 engages a shoulder 119 that limits its movement within annular space 120. A snap ring 127 is positioned above thrust washer 128 that also limits movement within annular space 120. A leak cock 132 is provided on housing 112 for supplying lubricant to first bearing 116 and second bearing 118.
A shaft cap 134 and static seals 136 are positioned within internal sleeve 114 to engage the drive shaft 26. Bolts 140 are used to tighten a rod clamp 142 around the drive shaft 26. Rod clamp 142 serves to preclude movement of internal sleeve 114 relative to the drive shaft 26. This ensures that internal sleeve 114 and the drive shaft 26 move as a unit and avoids relative movement that would cause wear of static seals 126.
Referring also to FIG. 1D, a mechanical seal 144 is disposed in annular space 120 between internal sleeve 114 and housing 112 to block the passage of produced well fluids into first bearing 116 and second bearing 118. A mechanical seal 144 has a first body 146 with a first sealing surface 150 and a second body 148 with a second sealing surface 156. First body 146 is secured to and rotates with internal sleeve 114. First body 146 secured to internal sleeve 114 with set screws 152. An o-ring seal 154 is positioned between first body 146 and internal sleeve 114 to serve a static sealing function. Second body 148 is secured to housing 112 by pins 158 and remains stationary with housing 112. Pin 158 projects into a travel groove 160 in housing 112ia so as to prevent rotation while permitting second body 148 to travel in groove 160 axially along housing 112ia. An o-ring seal 162 is provided between second body 148 and housing 112ia and serves a static sealing function.
Belville springs 164 are provided for biasing first sealing surface 150 and second sealing surface 156 in sealing engagement. A grease nipple 166 is provided on housing 112ia for supplying lubricant to mechanical seal 144. Apertures 115 are provided on top flange 112ib and bottom flange of housing 112ia for the purpose of mounting stuff box 16i. 
PC pumps are typically used in deep well applications such as pumping oil from wells. These pumps are often used to produce heavy crude oil. Heavy crude oil is often produced from semi-consolidated sand formations. Loose sand is readily transported to the stuffing box by the viscosity of the crude oil. Due the abrasive sand particles present in the crude oil, premature failure of the stuffing box, particularly the mechanical seal, is common in these applications. The drive head 12 must be removed to do maintenance work on the conventional stuffing boxes 16i,r. This necessitates using a service rig with two lifting lines, one to support the drive shaft 26 and the other to support the drive head 12. This costs oil companies money in service time, down time and environmental clean up. Costs associated with stuffing box failures are one of the highest maintenance costs on many wells.
Another prior art design places the stuffing box above the drive head so that the stuffing box may be replaced without removing the drive head. However, this means that the stuffing box is at an increased elevation requiring more service time to reach the stuffing box and increasing the risk of injury to service personnel. Another prior art design uses injectable seal material. This is not a good solution as the seal material flows out of the seal gland and therefore must be maintained often.
Therefore, there exists a need in the art for a stuffing box for a PC pump system that may be easily repaired.